Plunger Lift is the removal of fluid from the well formation using the formation gas as the motive source. All natural gas wells produce liquids with the gas flow. A problem arises when fluids accumulate in the well bore of a gas well. This fluid can be fresh water, salt water, condensate and/or oil that migrates toward the well bore with the gas movement. Oil and condensate have market value. In formations that produce unprofitable water, removal is desirable because the presence of water retards and stops the migration of gas to the well bore.
Newer, fast flowing wells atomize and blow this liquid to the surface. Older wells have (or develop) a lower gas to liquid ratio (GLR) that will not push all of the liquid up and out. In these wells, the fluid falls back down the tubing string, restricting the free flow of gas from the formation. A tall column of liquid in the tubing can completely and effectively stop the flowing gas well. Many wells had to be abandoned leaving significant amounts of oil and gas within the well because the flow rate had decreased or stopped completely.
The plunger was first employed for fluid removal about fifty years ago. The first plungers were solid rods with concentric grooves spaced along their outer surfaces. These grooves cause turbulence as gas blows past the plunger. Gas escapes past the plunger due to the absence of a sealing means. Turbulence produces drag which is an aid in lifting the plunger. This style is called a spiral plunger. There is of necessity an annulus between the spiral plunger and the inner wall of the tubing string. Gas can leak upwardly through this annulus.
More recently, U.S. Pat. No. 4,986,727 to Blanton discloses a pressure-operated oil and gas well swabbing device. The '727 reference claims a pressure activated valve comprising a pressure collapsible bladder means, a valve and seat interposed within the fluid passage and means connecting the valve and seat to the pressure collapsible bladder so that the valve and seat are closed when the bladder is collapsed to a degree corresponding to predetermined valve closing pressure. Fineberg in U.S. Pat. No. 4,984,969 teaches a plunger lift tool having a nose assembly to slow the descent of the tool into the well, a valve assembly, and a piston cylinder assembly. When the '969 tool is dropped, the gas and liquids in the well flow through restrictions in the nose assembly, thereby breaking the fall.
A pad plunger as disclosed in U.S. Pat. No. 4,531,891 improves the sealing efficiency relative to the efficiency of the above-described spiral plunger. The pad plunger comprises a central mandrel encircled by articulating segmented pads. The pad shapes vary from manufacturer to manufacturer. Four pads are the optimum number for segmented sealing. Between the mandrel and each pad is a suitable spring that pushes the pad outwardly for sealing contact with the well tubing wall. However, gas pressure still escapes between the pads and through the gaps in the various segments.
U.S. Pat. No. 4,984,970 to Flickman teaches an arrangement of coned disc for a valve pumping chamber. These arrangements are used in high pressure pumps. In the coned ring, a radial distance between the ends of the seal portions is provided to secure that the ring portion remains pressed against an adjacent portion when equal pressures appear on both axial ends of the coned portion. The coned ring is used in a pump to separate two different fluids from each other.
A valveless plunger system for well pumping is disclosed in Martin, U.S. Pat. No. 4,502,843. The groove and flange structure is used for gas pressure lift. The valveless plunger begins descent when the motor valve is closed. The plunger falls slowly under the influence of gravity. A timer opens the motor valve to enable gas to escape through a flow line. This creates a pressure differential across the plunger and drives the plunger upward.
The extant plungers do work in removing liquids from wells that can produce at least 300 cubic feet of gas for every barrel of fluid to be lifted 1000 feet. The problem of routinely removing fluid from oil and gas wells that have a G/L ratio below 300 cubic foot per barrel of fluid lifted 1000 feet remains.
One aspect of the problem to be solved is inefficiencies in the sealing means that is used to isolate the formation fluid from the formation gas as the plunger travels up the tubing/casing string. The typical plunger, moving upward, has fluid above it and gas below it. The plunger is a traveling interface between the gas and the fluid in the well tubing. Poor sealing causes the escape of gas past the plunger and consequently, a loss of gas pressure required for upward travel. Too tight a seal prevent rapid mobility and problems with the plunger becoming stuck within the well tubing. Another aspect of the problem is prior art plungers require that a well be shut in during the use of the plunger lift tool.
None of the references teach or suggest an auto-cycling plunger nor a method for auto-cycling plunger lift.
Consequently, there remains the need for an inexpensive and effective tool and simple method for rapidly and repeatedly removing liquids from low GLR wells. The problem of removing liquids without shutting in the well must also be addressed.